Mach Natural Resources (MNR) Q4 2025 Earnings Call

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Date

Friday, March 13, 2026 at 10 a.m. ET

Call participants

• Chief Executive Officer — Tom L. Ward
• Chief Financial Officer — Kevin R. White
• [Midstream/Accounting Executive] — Kent

Takeaways

• Total Distributions Since IPO -- $5.67 per unit paid from 2024, including the latest distribution of $0.53 per unit, representing an annualized yield of 15%.
• Full-Year Cash Return on Capital -- 23% achieved in 2025, compared to an average of greater than 30% over the last five years.
• 2025 Year-End Reserves -- 705 million barrels of oil equivalent, more than double compared to March 2025 figures.
• Reserve Additions -- Development program additions in 2025 exceeded the year's production by 18%.
• Q4 Production Volume -- 154,000 barrels of oil equivalent per day: 17% oil, 68% natural gas, 15% natural gas liquids.
• Average Realized Prices -- $58.14 per barrel of oil, $2.54 per Mcf of natural gas, $21.28 per barrel of NGLs.
• Q4 Revenues -- $331 million in oil and gas revenues composed of 42% oil, 44% gas, 14% NGLs; total revenues, including $42 million in hedges and midstream, reached $388 million.
• Adjusted EBITDA -- $187 million in Q4; operating cash flow was $169 million.
• Lease Operating Expense -- $106 million in Q4, or $7.50 per barrel of oil equivalent.
• Cash General & Administrative Expense -- $11 million, equating to $0.77 per BOE for the quarter.
• CapEx Discipline -- Q4 development CapEx was $77 million, representing 46% of operating cash flow; full-year 2025 development costs were $252 million, or 47% of operating cash flow.
• Distribution -- $89 million in Q4 cash available for distribution led to a payout of $0.53 per unit.
• Hedging Policy -- Hedging 50% of production in year one and 25% in year two on a rolling basis for near-term cash flow protection.
• Oswego Drilling Economics -- More than 250 Oswego locations have produced rates of return above 50% since 2021, with select wells exceeding 200%-400%.
• Deep Anadarko Update -- Three additional locations brought online, combining for approximately 40 million cubic feet of gas per day; projected estimated ultimate recovery of 19.5 Bcf per well and cost to drill and complete per location between $14 million and $15 million.
• San Juan Mancos Wells -- Plans for 7-8 new dry gas wells with three-mile laterals, each costing about $15 million and estimated to recover 24 Bcf, targeting cost reduction to $13 million per well during 2026 drilling season.
• Development Flexibility -- CapEx flexibility to shift between commodities; program will reduce Deep Anadarko rigs from two to one, and may add an oil rig in Oswego if crude prices stay above $70 per barrel.
• Leverage and Acquisition Strategy -- Debt to EBITDA ratio is at 1.3x, with a stated goal to return to 1.0x before pursuing further acquisitions.
• Corporate Decline Rate -- Corporate decline rate is low at 17%, supporting steady production without mandatory acquisitions.

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Risks

• Tom L. Ward said, "we need to move from the 1.3x leverage we have today down to a turn before we really start looking to bring on any more debt to make any acquisitions," indicating limited flexibility for acquisition growth until leverage is reduced.
• "We are seeing widening basis in the Anadarko and the San Juan," which the company attributes to weather but could indicate continued pricing pressure in regional gas markets.
• Ward said, "the restriction to any of this—we have too many locations that are good and not enough operating cash flow," suggesting CapEx is constrained by current cash generation.

Summary

Mach Natural Resources (NYSE:MNR) highlighted a significant doubling of year-end reserves, reflecting aggressive development and effective acquisition integration. Management confirmed a strict adherence to capital discipline, with reinvestment rates under 50% and a focused hedging strategy to preserve near-term cash flows. Mach Natural Resources maintained its quarterly distribution despite leverage at 1.3x, and reiterated plans to temporarily reduce Deep Anadarko rig count while retaining optionality to accelerate oil drilling programs if price conditions remain favorable. Guidance revisions incorporated a material increase in midstream profit estimates following updated plant throughput accounting and cost classification, providing additional visibility on non-upstream cash generation.

• Ward asserted, "Mach Natural Resources has never acquired an asset by paying more than PDP PV-10," underscoring disciplined M&A execution.
• The planned drilling focus in 2026 pivots back to San Juan and Deep Anadarko gas assets in the first half, with flexibility to redirect capital to oil targets if pricing holds above $70 per barrel.
• Ward noted, "to, I believe, the Mancos will be our highest rate of return project as soon as we lower some costs," signaling internal confidence in project economics and anticipated cost optimization.
• Mach Natural Resources emphasized that low corporate decline rates and strong asset inventory allow production maintenance without requiring immediate acquisitions.

Industry glossary

• PDP PV-10: Present value of proved developed producing reserves, discounted at 10% per annum, used as a basis for disciplined asset acquisition.
• BOE: Barrels of oil equivalent, a standard measure combining oil, gas, and NGL volumes on an energy-equivalent basis.
• HBP: Held By Production, indicating acreage that remains under lease so long as oil or gas is produced in paying quantities.
• GP&T: Gathering, Processing, and Transportation; refers to midstream processes and associated expenses or revenues.
• NGL: Natural Gas Liquids, components of natural gas that are separated as liquids at processing plants.
• Bcf: Billion cubic feet, a volumetric measurement of natural gas production or reserves.

Full Conference Call Transcript

Tom L. Ward: Thank you, Rob. Welcome to Mach Natural Resources LP fourth quarter earnings update. Each quarter, we reiterate the company's four strategic pillars that have guided us since our founding in 2018. Since inception, the company has put a distinct emphasis on delivering exceptional cash returns through distributions. We have distributed back to our unitholders a total of $1.3 billion starting in 2018 after our first acquisition, showcasing our consistent and dependable nature across a variety of commodity cycles. We also have remained a consistent distributor of cash to our unitholders post our public offering. Mach Natural Resources LP has delivered distributions totaling $5.67 per unit from 2024 through our last announced distribution of $0.53.

This is an annualized yield of 15%. I doubt that you will hear another energy company talk about cash returns. However, that is the lifeblood of our business and what makes us different. Additionally, we have delivered an average cash return on capital of greater than 30% over the last five years and 23% in 2025 during a down cycle. Clearly, one of the best records of all public equities, not just energy. Therefore, of our four pillars, maximizing distributions is the culmination of the other three and the most important. The second pillar is disciplined execution. Mach Natural Resources LP has never acquired an asset by paying more than PDP PV-10.

In other words, all the blue sky of the company, the acreage, midstream, equipment, offices, are part of our purchase price. We have accomplished this goal 23 times and do not see an end to the requirement. Through this method of deploying capital, we have been diligent in assembling a set of assets across the Mid-Con and San Juan Basin that have drilling opportunities that we did not have to pay for. Most of our contemporaries are willing to pay millions of dollars per location when they buy into fashionable areas. What we have done is to buy in at least two areas that were seen as distressed when actually they were not.

Since 2018, we have spent $1.4 billion developing assets that others thought were worth zero while compiling acreage that now amounts to nearly 3 million acres. And the distinct luxury of having so much acreage with a very low cost basis is the ability to sell to generate cash. Currently, the Mid-Con and San Juan are seeing renewed outside investment searching for drilling rights. Also, the Deep Anadarko is the only place we have expended capital to lease land. The vast majority of our acreage is held by production from the purchases that we have made.

We will test the market and see if we can recoup any of our costs for acreage, seismic, and other expenses associated with the Deep Anadarko. As I mentioned, the San Juan is also now very active with additional sales processes, which are paying for upside where we did not. However, our land in the San Juan is all held by production, and we are not in any hurry to sell there. We have done extremely well buying distressed properties then finding them not in distress sometime later. For example, the Sabinol purchase, which closed last September, was bought when the market was certain we would see oil prices below $50.

We believe that anytime you can buy a stable crude production in the sixties, you will be rewarded at some point. This philosophy also drives our hedging decisions. We hedge 50% of our production in year one, 25% in year two on a rolling basis. We want to lock in near-term cash flow while having exposure to higher prices in the future. We have a strong belief that our business will be critical to the world over the next few decades and prices will have the tendency to rise faster than the rate of inflation during this time.

Our peers have moved to asset-backed securities to purchase production, which takes away future upside and introduces risk from higher prices rather than reward. During the last year, we have moved from drilling oil dominated assets in the Oswego and condensate window of the STACK to dry gas locations in the Deep Anadarko and San Juan. Our reasoning is simple. The Bloomberg fair value price for West Texas Intermediate crude oil was $71.72 in 2024. That reduced to $57.42 in 2025. The Bloomberg fair value price for Henry Hub natural gas was $3.43 in 2024. That price improved to $4.42 in 2025.

In 2026, our drilling is once again concentrating on drilling natural gas wells in the San Juan and Deep Anadarko through the first half of this year. However, we are now preparing to bring back an oil rig in the Oswego and associated oil areas in the last 2026, if crude prices remain elevated. As you can see in the presentation updated this morning, the Oswego drilling program is very good. Since 2021, we have drilled and completed more than 250 Oswego locations, which have consistently had rates of return above 50%. We also have locations on the Red Fork, Sycamore, and Osage that can be added to our drilling schedule.

Therefore, we will plan to reduce the Deep Anadarko CapEx by moving from two rigs to one rig and bring back on the Oswego program if the market allows. The flexibility to choose which commodity to produce depending on the price is one of the hallmarks of our company. The third pillar to discuss is disciplined reinvestment rate. Our goal is to return as much cash to our unitholders as possible while staying within the guidelines for our strategic principles. We target a reinvestment rate of no more than 50% to maximize cash distribution while maintaining production and profitability. In 2026, we anticipate slightly growing our barrels of oil equivalent while maintaining our desired reinvestment rate.

It is a task that is difficult to accomplish, especially with a set of assets that at the time of purchase were not supposed to have any upside value. However, we have not only accomplished this over the past eight years, but have thrived by drilling very high rates of return projects. In 2024, we projected our rate of return on drilling projects to be approximately 55%. In 2025, we made the move from oil to natural gas to maximize the rate of return in a difficult price environment. We succeeded by delivering rates of return of approximately 40%. Since our last earnings release, we have brought on production three additional Deep Anadarko locations.

These three locations combined for approximately 40 million cubic feet of gas per day. In the Deep Anadarko, we anticipate an estimated ultimate recovery of approximately 19.5 Bcf or 6.5 Bcf per mile of lateral. We believe ranges will be between 5 Bcf to 8 Bcf per mile of lateral. The Deep Anadarko is located, as the name implies, at a true vertical depth of between 14,000 to 17,000 feet. Drilling an additional 15,000 feet of lateral makes total depth between 29,000 to 32,000 feet. Our cost to drill and complete are projected to be between $14 million to $15 million per location. In the San Juan, we plan to drill seven to eight dry gas Mancos wells.

The true vertical depth of the Mancos is approximately 7,000 feet, and laterals are projected to be a mixture of two and three miles. A three-mile horizontal lateral Mancos well is projected to cost $15 million and recover approximately 24 Bcf of reserves with a 60% first-year decline. Our goal is to lower the drilling and completion cost to approximately $13 million during the 2026 drilling season. The drilling season starts on April 1 and runs through November. The fourth pillar to discuss is to maintain financial strength. Our long-term goal is to have a debt to EBITDA ratio of one times.

When we are at that level of leverage, we start to look for additional acquisitions that fit the pillar of disciplined execution. This is a self-imposed guideline to provide financial strength in any commodity price environment. Keeping our leverage low also enables us to flex upwards as we did for the Transformity, iCAV, and Sabinol acquisitions that closed in Q3 2025. By maintaining low leverage, we can toggle between drilling and acquisitions when opportunities arise in either direction. Currently, during a time when we are not looking to make an acquisition, we can maintain our production levels through drilling due to our low corporate decline of 17%.

In other words, we do not have to make any acquisitions unless they fit within the parameters we have set to achieve our goal of maintaining production while deploying only 50% of our operating cash flow while sending home all of our excess cash. We continue to believe in the long-term value of oil and natural gas. Our acquisition strategy continues to achieve the results we desire. We believe in patience and resilience. Rushing and forcing outcomes may not yield the best results. It is often good to remind oneself to remain calm and persistent while waiting on our desired outcome. As the proverb says, good things come to those who wait.

I will now turn the call over to Kevin R. White for the financial results.

Kevin R. White: Thanks, Tom. 2025 year-end reserves, capturing the results of 2025 drilling and acquisitions during the year, more than doubled from March to 705 million barrels of oil equivalent. Also worth noting, the additions from the results of our development program exceeded the 2025 production by 18%. For the quarter, our production of 154,000 BOE per day was 17% oil, 68% natural gas, and percent NGLs. Our average realized prices were $58.14 per barrel of oil, $2.54 per Mcf of gas, and $21.28 per barrel of NGLs. Of the $331 million in total oil and gas revenues, the relative contribution for oil was 42%, 44% for gas, and 14% for NGLs.

On the expense side, our lease operating was $106 million for the quarter or $7.50 per BOE. Cash G&A for the quarter was $11 million or $0.77 per BOE. We ended the quarter with $43 million in cash and $338 million of availability under the credit facility. Total revenues, including our hedges, which contributed $42 million, and midstream activities totaled $388 million. Adjusted EBITDA was $187 million and $169 million of operating cash flow and development CapEx of $77 million or 46% of our operating cash flow. Full-year 2025 development costs of $252 million represented 47% of our operating cash flow.

In the quarter, we generated $89 million cash available for distribution, resulting in a distribution of $0.53 per unit, which was paid out yesterday. Rob, I will turn the call back to you to open the line for questions.

Operator: Thank you. We will now open for questions. We will be conducting a question-and-answer session. Thank you. Our first question is from the line of Neal Dingmann with William Blair. Please proceed with your questions. Tom, nice details this morning.

Neal Dingmann: Just a question. You mentioned about possibly bringing the additional rig at the Oswego to take advantage of higher oil. Just curious, are there other things? Is there a secondary activity? Are there other things that you are kind of deliberating to do that you could do to continue to take advantage of oil prices as well?

Tom L. Ward: Yes, Neal, I think right now, if we only look to have one rig running for the last half of the year, it is only going to spend about $25 million. I would love for prices to stay where they are and give us a little more operating cash flow and maybe bring on another oil rig to drill some of the Red Fork locations that we had or even the Southern Oklahoma assets that we have not yet been able to get to because of lower prices after making the FlyCatcher acquisition. So if we could, it all depends on staying within our 50% of operating cash flow.

So as long as our cash flow can move up a bit, we would maybe put a second rig in and out to be bringing on more oil if it is staying in the seventies. As you know, anytime oil is up in the $70 range, we make very good rates of return and are competitive with our iCAV and Deep Anadarko gas wells.

Neal Dingmann: Great. Great details. And then just secondly, maybe a bit early on, prices have not been terribly high yet for just a couple of weeks. Do you see anything in the M&A market? I mean, oftentimes, sometimes spreads start to widen when we see periods like this. Is it early? Are you still seeing opportunities? Maybe just any generalities you can sort of comment around that, the M&A market?

Tom L. Ward: Yes, we are pretty much on the sidelines for M&A until we move down our debt. So we need to move from the 1.3x leverage we have today down to a turn before we really start looking to bring on any more debt to make any acquisitions. So our focus is to pay down debt, and then we might be able to do that though by bringing a partner in the Deep Anadarko. We will see. We do not know yet. We are hopeful to do that.

That also, if we did in the Deep Anadarko, we would be able to keep two rigs working and have just less working interest and still cut back our costs, remembering that we are going to spend over a couple hundred million dollars this year drilling wells there. So to answer your question directly, we are not really in the market looking, and really we were never competitive for these larger transactions that are going on just because of the amount of debt that it requires for us to be competitive.

So what we can do is buy a larger transaction by using some equity and some debt, and we hope to be back in the market here this year as we pay down our debt.

Neal Dingmann: Bob, could you monetize midstream to get that debt down quicker?

Tom L. Ward: Oh, we could, but then you just pay for it in the long run. So with the midstream systems that we paid nothing for, they give us a good string of cash flow, and so I personally do not like to sell those off just because over the long term, they are good for the company.

Operator: Thanks so much. Thank you. Our next questions are from the line of Derrick Lee Whitfield with Texas Capital. Please proceed with your questions.

Derrick Lee Whitfield: Good morning, guys, and great year-end update.

Tom L. Ward: Thanks, Derrick.

Derrick Lee Whitfield: In your prepared comments, you seem to highlight the desire to monetize assets across the portfolio that could be experiencing a rerate in value based on the current macro environment. Could you place some parameters around the value of types of transactions that you are looking at just to, again, help us calibrate the type of opportunities that you have?

Tom L. Ward: Yes, I would like to. I do not really know what size we are talking about because we have not really negotiated anything. So, what I would love to do is pay down some debt so that we can get back in the acquisition market without affecting our distributions. So obviously, there are three ways that we can bring our debt down, which is debt to EBITDA would be prices moving up. That is a simple way, and it is happening now. And then along with that, you could cut your distributions back and pay down debt that way, which is not our preference, or we could sell some non-EBITDA-generating assets.

The Deep Anadarko is the only area that is not HBP and has leasehold that has some term on it. So it seems like the most likely place that we would sell some acreage. So, you know, the size I cannot really say. We will know here very quickly, but it has to be significant or else we would just do it ourselves.

Derrick Lee Whitfield: And Tom, just on the Deep Anadarko, could you, I guess, frame where we are from an acreage position with that trend now?

Tom L. Ward: Yes. We are about 50,000 acres, which is about all we want if we are not going to bring in a partner. We can effectively drill that out over the time of our term on the leasehold. So if we do not bring in a partner, we will not spend more in the second half of our leasehold CapEx. So that is the way we look at it. We will bring in a partner and have some additional acreage that we will be putting on and drilling more wells over the course of the next five years, or we will just stop where we are and drill out what we have.

Derrick Lee Whitfield: Makes sense. And maybe just shifting over to operations. Wanted to focus on your recent Deep Anadarko and Mancos wells. With the benefit of a few at-bats in these formations, could you speak to how you performed against pre-drill expectations and some of the levers you are planning to pull to drive lower completed well costs?

Tom L. Ward: Yes. The first few wells that we drilled in the Deep Anadarko were better than anticipated. The last three, I think, are right on our type curve. So I would say it is performing as expected. The Mancos is just better than expected. I think it is a world-class reservoir. Too much money has been spent on drilling and completing wells there over the past, and we look forward to, I believe, the Mancos will be our highest rate of return project as soon as we lower some costs. I am confident that our team will be able to do that. Thank you.

And just expanding others, there is just no reason that the Mancos well at 7,000 feet and an easy shale target to drill should cost more than one of the most difficult wells to drill in the country in the Deep Anadarko. So I just do not believe it will.

Operator: Our next question comes from the line of Charles Arthur Meade with Johnson Rice. Please proceed with your question.

Charles Arthur Meade: Good morning. Tom and Kevin and the rest of the team there. Tom, I wanted to ask about the Oswego and, I guess, maybe two questions about the Oswego. First, I think you addressed this, but just to make it clear, what oil price would you need to see to make you want to go forward with that rig in the back half of the year, targeting the oily Oswego?

Tom L. Ward: Yes, even right now the Oswego competes with the Deep Anadarko from rates of return. So I think anytime that you have oil above $70, we will have rates of return well north of 50%. And that meets the requirement of having capital shipped to it. And what we should do in a market like that is to distribute out to all three, the Deep Anadarko, the Mancos, and the Oswego, and that is what we are attempting to do.

Charles Arthur Meade: Got it. Thank you for that. And I think—

Tom L. Ward: Charles, to look at our Oswego—oh, I am sorry. To look at our Oswego program and say what we can achieve, just look at the difference between the—you know, if you look at an old presentation of ours, in 2024, we show every well we drilled. And then we show every well we drilled in 2025, and the Oswego wells are equivalent overall but just a higher rate of return in 2024 due to pricing. And so it is a very consistent well. The wells are not consistent. They have good wells and bad wells that you do everywhere, but overall, you get a very consistent return.

Charles Arthur Meade: Right. And that is actually a good lead into my follow-up question because that is one of the things that I noticed on your slide 14 is that you have some—there is a wider variance on those Oswego wells, and I know we have spoke about before. But I wondered if you could tell me—these four really fabulous wells on the left side of your skyline chart here, are those all in the same section? And really what I am getting at is, you know, are there sticks on the map for you to come in and lay some wells in the back half of '26 that are right alongside some of these four really fabulous ones?

Tom L. Ward: Yes. As in all things, they are a little more complex. So we are drilling inside of a field that has vugular porosity and algal mounds, so you have different thicknesses. So wells even that are fairly close together can have different amounts of porosity that has either been drained or not drained. And in the past, what we have seen is that if you stay 660 feet apart, you really do not have interference across the play. But you just do not know until you drill a well. You can stay within the system, and you can feel very comfortable that you are going to have some really good wells like this.

And again, we probably should have showed the 2024 drilling results because we have the same thing. We have wells that have 300% or 400% rates of return, and then others that might have just a 10% to 20% rate of return, and they can be right next to each other or they can be in different sections. So to answer your question, yes, we have many, many locations left to drill. I feel comfortable that they are going to be north of 50% rate of return once we get the program done. I cannot tell you which ones are going to be 200%.

Charles Arthur Meade: Got it. Thank you, Tom. You bet.

Operator: The next question is from the line of Michael Stephen Scialla with Stephens. Please proceed with your questions. Hi, good morning. I wanted to ask on your guidance. You included wider differentials on natural gas. And it seems like there is ample takeaway capacity in both the Mid-Con and San Juan. So can you talk about what caused you to make that change and what you are seeing in those local markets? And maybe tie that into how you are feeling about the gas macro in general?

Tom L. Ward: We are seeing widening basis in the Anadarko and the San Juan. So all we do is try to estimate from the past what we have seen and bring that into the future. Do I personally believe that the San Juan, for example, is going to be wider going forward? I do not. I think the same reasons that you have warm weather in the West has caused basis to widen, and I think that as you have low hydro in the West, you will see basis tighten over the course of the year. That is just anybody's guess, but that is mine. And then I think that the takeaway is not an issue.

So if you look back over five years in the San Juan, the production is the same. So it is driven by oversupply to increase or loosen the basis. And the same way in Anadarko, we are not seeing this from a supply perspective. So it is just weather and a fairly warm winter that has widened basis, in my opinion.

Michael Stephen Scialla: Appreciate that, Tom. Thanks. I wanted to ask on the Mancos. I know you talked about the well cost. Do you think you can drive those down with different completion style? I know you completed those three-mile laterals, I think, with less proppant per foot than what has been done there previously. I wanted to see how those are performing now that you have had a little bit more time to look at them relative to the other wells in the play?

Tom L. Ward: Yes, they are the same. It is not a lack of proppant. We are still using 2,000 pounds a foot. It is just that others have been using more, which in my opinion, I do not think is needed. We could probably use less than we do, but where we are going to save money is not only on how much proppant we use, but just the focus on saving, just really looking at the best ways to transport sand and chemicals and rig costs. In my opinion, the San Juan over the course of time has been run by majors who spend too much money, and we need some independents in here to cut costs.

No different than it would be if a major was trying to drill in the Anadarko Basin. They just cannot do it as well as we can. So I think we will save money just by watching what we do.

Michael Stephen Scialla: Sounds good. Thanks, Tom. Thank you.

Operator: The next questions are from the line of John Christopher Freeman with Raymond James. Please proceed with your questions.

John Christopher Freeman: Thanks. Good morning. The biggest change from your previous '26 guidance was the midstream profit where you all raised the guidance by about 40%. Can you just sort of speak to what drove that significant of an improvement?

Kent: Yes. Hey, John, this is Kent. When we first came out with pro forma guidance to capture the effects of the two transactions last year, iCAV and Sabinol, we did not anticipate some accounting treatment on kind of our own throughput volumes through one of the plants on iCAV. And as a result of looking at Q4, a full quarter of results, we are seeing that there is some MOE midstream operating expense being reclassed to GP&T. We have captured both components of that in the new guidance, and they are offsetting, but it does improve midstream operating profit.

John Christopher Freeman: Thanks for that color, Kent. And then just one quick one for me following up. Are you all looking to take advantage right now of what we have seen on the oil move by adding more hedges? Are you all sort of like kind of waiting to see how this plays out?

Tom L. Ward: Yes. If you look at the back of the curve, really anything outside of the next three to six months, the curve falls off fairly quickly. So no, we like to stay—I like having access to commodity movement. And so we do not want to be more than 50% hedged in year one and 25% in year two. And we use that as mainly a mechanical hedge just to guarantee cash flows. But let us, for example, if we had no debt like we did in 2023, we would not have any hedges on. So I want exposure to the curve.

John Christopher Freeman: Thanks, Tom. Appreciate it.

Tom L. Ward: Thank you, John.

Operator: The next question is from the line of Jeffrey Grampp with Northland Capital Markets. Please proceed with your question.

Jeffrey Grampp: Good morning, guys. First question, I just kind of want to clarify that the current guidance, does that contemplate that shift to the Oswego rig in the second half, or is that just kind of, I guess, some optionality or some assessments that you guys will do over the next handful of months?

Kevin R. White: It did not.

Jeffrey Grampp: Okay, perfect. Thanks. For my follow-up, it looks like you guys, I think, were planning some Fruitland coal wells as well for '26. It looks like those have been removed. Is that just a function of the bullishness you guys have of the seven to eight wells in the Mancos?

Tom L. Ward: If we can pull in another well in the Mancos, we would like to do that. Our Fruitland coal is a very good reservoir, consistent reservoir for us to drill. It will be easier next year in the 2027 program to bring on more of those. And, again, it is all associated with how much operating cash flow we have. So the restriction to any of this—we have too many locations that are good and not enough operating cash flow.

Jeffrey Grampp: Yes. Not a bad problem to have. I appreciate the time. Thank you.

Operator: Thank you. At this time, we have reached the end of our question-and-answer session. That will also conclude today's conference. Thank you for your participation. You may now disconnect your lines at this time. Have a wonderful day.

Tom L. Ward: Thanks, Rob.

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